1. Field of the Invention
This invention is directed toward artificial lift systems used to produce fluids from boreholes such as oil and gas wells. More particularly, the invention is directed toward an improved downhole progressive cavity pump that is inserted and operated within a borehole, and subsequently removed from the borehole, using a coiled or conventional sucker rod, or other rotatable strings that may be used to transmit torque to the pump.
2. Background of the Related Art
Modern oil and gas wells are typically drilled with a rotary drill bit and a circulating drilling fluid or xe2x80x9cmudxe2x80x9d system. The mud system (a) serves as a means for removing drill bit cuttings from the well as the borehole is advanced, (b) lubricates and cools the rotating drill bit, and (c) provides pressure within the borehole to balance internal pressures of formations penetrated by the borehole. Rotary motion is imparted to the drill bit by rotation of a drill string to which the bit is attached. Alternately, the bit is rotated by a mud motor which is attached to the drill string just above the drill bit. The mud motor is powered by the circulating mud system. Subsequent to the drilling of a well, or alternately at intermediate periods during the drilling process, the borehole is cased typically with steel casing, and the annulus between the borehole and the outer surface of the casing is filled with cement. The casing preserves the integrity of the borehole by preventing collapse or cave-in. The cement annulus hydraulically isolates formation zones penetrated by the borehole that are at different internal formation pressures.
Numerous operations occur in the well borehole after casing is xe2x80x9csetxe2x80x9d. All operations require the insertion of some type of instrumentation or hardware within the borehole. Examples of typical borehole operations include:
(a) setting packers and plugs to isolate producing zones;
(b) inserting tubing within the casing and extending the tubing to the prospective producing zone; and
(c) inserting, operating and removing pumping systems from the borehole.
Fluids can be produced from oil and gas wells by utilizing internal pressure within a producing zone to lift the fluid through the well borehole to the surface of the earth. If internal formation pressure is insufficient, artificial fluid lift means and methods must be used to transfer fluids from the producing zone and through the borehole to the surface of the earth.
The most common artificial lift technology utilized in the domestic oil industry is the sucker rod pumping system. A sucker rod pumping system consists of a pumping unit that converts a rotary motion of a drive motor to a reciprocating motion of an artificial lift pump. A pump unit is connected to a polish rod and a sucker rod xe2x80x9cstringxe2x80x9d which, in turn, operationally connects to a rod pump in the borehole. The string can consist of a group of connected, essentially rigid, steel sucker rods sections (commonly referred to as xe2x80x9cjointsxe2x80x9d) in lengths of 25 or 30 feet (ft), and in diameters ranging from ⅝ inches (in.) to 1-xc2xc in. Joints are sequentially connected or disconnected as the string is inserted or removed from the borehole, respectively. Alternately, a continuous sucker rod (hereafter referred to as COROD) string can be used to operationally connect the pump unit at the surface of the earth to the rod pump positioned within the borehole. A delivery mechanism rig (hereafter CORIG) is used to convey the COROD string into and out of the borehole.
Prior art borehole pump assemblies of sucker rod operated artificial lift systems typically utilize a progressive cavity (hereafter PC) pump positioned within wellbore tubing. A typical prior art insertable PC pump system will be described, and includes a pump subsection consisting of a rotor operating within a stator. A tag bar/no-turn subsection is connected below the stator/rotor assembly. Typically, a flush tube extension is connected above the stator/rotor assembly, with a seating/no-go assembly and a cloverleaf pick-up positioned above the flush tube extension. The prior art insertable PC pump assembly requires a special joint of tubing containing a pin protruding into the interior of the tube. A pump seating nipple is also required above the special joint of tubing. It should be understood that the discussed prior art system is used as an example, and that variations of the discussed system using, as examples, different hold down systems and different torque stopping devices are in the prior art.
The prior art PC pump rotor and stator, flush extension tube, cloverleaf pick-up and seating/no-go components are all assembled prior to insertion into the borehole tubing thereby creating an insertable PC pump assembly.
Before the PC pump is positioned and operated down hole, the previously mentioned special joint of tubing with pin and attached seating nipple must be installed in the tubing string so that the pump will be positioned to lift from a particular producing zone of interest. If the pump assembly is subsequently positioned at a shallower or at a deeper zone of interest within the well, this can be accomplished by removing the tubing string, or by adding or subtracting joints of tubing. This repositions the special joint of tubing as required.
Once the special tubing and seating nipple are installed in the tubing string, the insertable PC pump assembly is run, from surface of the earth, downhole inside of the tubing by a COROD or a conventional sucker rod system. When reaching the special tubing joint, a forked torque slot at the lower end of the insertable PC pump assembly tag bar/no-turn subsection aligns with the pin protruding near the bottom in the special tubing joint. Once the torque fork aligns with and engages the pin, the insertable PC pump assembly is locked radially within the tubing and can not spin within the tubing when the pump is operated. After the torque fork and pin have aligned, the seating/no-go assembly located at the top of the PC pump then slides into and seals in the seating nipple until it is stopped by the no-go. The prior art insertable PC Pump is now completely installed down hole.
The prior art insertable PC pump is removed by lifting the sucker rod string until a coupling on the top of the rotor shoulders out on the clover leaf located on the top of the extension tube just below the seating/no-go assembly. The seating/no-go assembly is then extracted from the seating nipple, and the insertable PC pump assembly can be pulled, using COROD or conventional sucker rod string, to surface for servicing or repositioning. Once pulled, a new insertable PC pump of identical length and identical outside diameter can be installed as outline above.
The operating envelope of an insertable PC pump is dependent upon pump length, pump outside diameter and the rotational operating speed. In the prior art system, the pump length is essentially fixed by the distance between the seating nipple and the no turn pin in the special joint of tubing. Pump diameter is essentially fixed by the seating nipple size. Stated another way, these factors define the operating envelope of the pump. For a given operating speed, production volume can be gained by lengthening stator pitch and decreasing the total number of pitches inside the fixed operating envelope. Volume is gained at the expense of decreasing lift capacity. On the other hand, lift capacity can be gained within the fixed operating envelope by shortening stator pitch and increasing the total number of pitches. Production volume can only be gained, at a given lift capacity, by increasing operating speed. This, in turn, increase pump wear and decreases pump life. For a given operating speed and a given seating nipple sizes, the operating envelope of the prior art system can only be changed by pulling the entire tubing string and adjusting the operating envelope by changing the distance between the seating nipple and the special joint of tubing containing the locking pin. Alternately, the tubing can be pulled and the seating nipple can be changed thereby allowing the operating envelope to be changed by varying pump diameter. Either approach requires that the production tubing string be pulled at significant monetary and operating expense.
During operation, it is possible that the insertable PC pump assembly may need to be flushed to remove sand and other debris from the stator/rotor subsection. To perform this flushing operation, the rotor component is pulled upward from the stator by means of the sucker rod string. In order to avoid disengaging the entire pump assembly from the seating nipple, the rotor is moved upward only until it is located in the flush tube between the seating/no-go assembly and the stator/rotor subassembly. The pump may now be flushed, and then the rotor reinstalled without completely reseating the entire pump assembly. Since the prior art insertable PC pump assembly is picked up from the top of the rotor, the flush tube extension assembly is required. Furthermore, the length of the flush tube extension must be at least as long as the rotor, for reasons that will become apparent in a subsequent section of this disclosure. The entire assembly will then be at least twice as long as the stator. This presents a problem in optimizing stator length within the operation, and clearly illustrates a major deficiency in prior art insertable PC pump systems.
In summary, the prior art insertable PC pump system described above requires a special joint of tubing containing a welded, inwardly protruding pin for radial locking and a seating nipple. The seating nipple places some restrictions upon the inside diameter of the tubing in which the pump assembly can be operated. This directly constrains the outside diameter of the insertable pump assembly. The overall distance between the pin and the seating nipple constrains the length of the pump assembly. In order to change the length of the pump assembly to increase lift capacity (by adding stator pitches) or to change production volume (by lengthening stator pitches), (1) the entire tubing string must be removed and (2) the distance between the seating nipple and the locking pin must be adjusted accordingly before the tubing is reinserted into the well. Axial repositioning of the pump without changing length can be done by adding or subtracting tubing joints to reposition the seating nipple and the locking pin as a unit. The prior art PC pump assembly requires a flush tube assembly so that the rotor can be removed from the stator for flushing. This increases the length of the assembly, and also adds to the mechanical complexity and the manufacturing cost of the assembly.
As noted previously, other prior art insertable PC pump systems are commercially available. All systems, however, comprise the above discussed limitations of fixed seating nipple inside diameter, fixed length between seating nipple and a rotational locking device, pick up from the top of the rotor, and an extension tube.
The present invention is an improved insertable progressive cavity (PC) borehole pump assembly for use in any rotational operated artificial lift systems. The PC pump subsection consists of a rotor operating within a stator. The lower end of the rotor is terminated with a retaining structure that will hereafter be referred to as an xe2x80x9carrowheadxe2x80x9d. A torque restraining tool subsection is connected to the stator/rotor assembly. A seating/no-go pick up housing and floating ring subassembly is connected above the stator/rotor assembly. Alternately, the seating/no go can be located below the stator but the floating ring subassembly must always be above the stator. A pump seating nipple is used in the tubing string to receive and seat the pump assembly at the seating subassembly.
The PC pump subsection containing (a) the arrowhead attached to the rotor, (b) the torque restraining subsection, and (c) the seating/no-go pick up housing and floating ring assembly are assembled at the surface thereby creating the insertable PC pump unit. Before the insertable PC pump is installed downhole, the seating nipple is first installed in the tubing string. After seating nipple installation, the insertable PC pump assembly is then inserted in the borehole, inside of the tubing, preferably by means of COROD or conventional sucker rod system from surface of the earth. Other rotatable string means, such as tubing, can be used for insertion and operation. Furthermore, the system does not necessarily have to be operated inside production tubing, but can operate in other tubular strings such as casing. In one embodiment, all components of the pump assembly, including the torque restraining subassembly, pass through the seating nipple with the exception of the seating/no-go pick up housing and floating ring assembly. In other embodiments, some components can pass through or stay above the seating nipple, depending upon the location of the mandrel and the no-go. If the system is configured so that the seating nipple is at the bottom of the pump, the stator will not pass through the seating nipple but the torque restraining xe2x80x9cno-turnxe2x80x9d may or may not pass through. If the seating nipple is at the top of the assembly, the stator will pass through the seating nipple but the no-turn may or may not pass through the seating nipple. The no-turn is positioned at the top or the bottom thereby determining if it must pass through the seating nipple or not. The housing seats and seals in the seating nipple, and is stopped by the no-go. Pump intake and exhaust are isolated by the seal. At this point, the insertable PC pump assembly is completely installed.
The insertable PC pump assembly is removed from the wellbore by lifting the sucker rod string thereby pulling the rotor through the stator and through the floating ring, until the arrowhead on the bottom of the rotor reaches the floating ring. The arrowhead is sized so that it can not pass through the floating ring, but will freely move through the stator. When the rotor is lifted to a point where the arrowhead engages the floating ring, continued lifting of the sucker rod pulls the entire insertable PC pump assembly from the seating nipple. The pump can now be conveyed to surface by a COROD rig, by conventional sucker rod pulling means and procedures, or by other rotatable tubular pulling means. In an alternate embodiment, the tubular can be non-rotating. In this embodiment, the non-rotating tubular is terminated downhole with a rotating drive means which, in turn, provides the needed rotational motion to operate the pump system.
As with prior art PC pumps, it is possible that the insertable PC pump assembly set forth in this disclosure may need to be flushed of sand and other debris. This is accomplished by pulling, by means of the sucker rod string, the rotor out of the stator and through the pick up housing until the arrowhead is positioned between the top of the stator rubber and the floating ring. This positions the stator and rotor so that the pump can be effectively flushed. After flushing, the procedure is essentially reversed so that the rotor is again positioned within the stator for pump operation.
Prior art insertable PC systems require a special tubing joint with an internally protruding welded pin to insure that the assembly does not rotate. The pin to seating nipple distance limits the length of the pump assembly. The improved insertable PC pump assembly requires no special tubing joint with an internally protruding, welded pin to insure that the assembly does not rotate. The torque restraining subassembly, which is an integral part of the insertable pump unit, is used to releasably grip the interior of the tubing thereby preventing rotation of the stator assembly during operation. The improved insertable PC pump assembly can be removed, the length can be varied thereby allowing changes in volumetric displacement and/or lift capacity, and the assembly can be reinstalled in the same seating nipple as long as the outside diameter of the insertable PC pump assembly is compatible with the dimensions of the seating nipple. This is possible because the torque restraining assembly can releasably grip the interior of tubing at any axial position. No restraining pin is required. The pump can be removed and adjustments in volumetric displacement and/or lift capacity can be made by varying pump length and without having to remove tubing and altering the spacing between a seating nipple and a no turn pin as in prior art systems.
Since the previously discussed prior art insertable PC pump assembly picks up from the top of the rotor, the flush extension tube is required. Furthermore, the flush tube must be at least as long as the rotor. The stator/rotor subsection must, therefore, be at least twice as long as the stator. The improved PC pump assembly picks up from the bottom of the rotor, therefore no flush tube is required. When configured for flushing, the rotor extends substantially into the production tubing thereby allowing the length of the improved pump assembly to be reduced to almost half the length of the prior art system. The improved insertable PC pump can therefore be fabricated for larger production volumes and higher lifts within a tightly constrained operating envelope defined by outside diameter and length.
The improved insertable PC pump assembly contains fewer special parts and therefore is less costly to manufacture, to operate, and to maintain.